Note: Descriptions are shown in the official language in which they were submitted.
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PETROLEUM RECOVERY PROCESS AND SYSTEM
Field of the Invention
The present invention is directed to a method of recovering petroleum from a
formation, in particular, the present invention is directed to a method of
enhanced oil
recovery from a formation.
Background of the Invention
In the recovery of petroleum from subterranean formations, it is possible to
recover
only a portion of the petroleum in the formation using primary recovery
methods utilizing
the natural formation pressure to produce the petroleum. A portion of the
petroleum that
cannot be produced from a formation using primary recovery methods may be
produced by
improved or enhanced oil recovery (EOR) methods. Improved oil recovery methods
include waterflooding. EOR methods include thermal EOR, miscible displacement
EOR,
and chemical EOR. Thermal EOR methods heat the petroleum in a formation to
reduce
the viscosity of the petroleum in the formation thereby mobilizing the
petroleum for
recovery. Steam flooding and fire flooding are common thermal EOR methods.
Miscible
displacement EOR involves the injection of a compound or mixture into a
petroleum-
bearing formation that is miscible with petroleum in the formation to mix with
the
petroleum and reduce the viscosity of the petroleum, lowering its surface
tension, and
swelling the petroleum, thereby mobilizing the petroleum for recovery. The
injected
compound or mixture must be much lighter and less viscous than the petroleum
in the
formation¨typical compounds for use as miscible EOR agents are gases such as
CO2,
nitrogen, or a hydrocarbon gas such as methane. Chemical EOR involves the
injection of
aqueous alkaline solutions or surfactants into the formation and/or injection
of polymers
into the formation. The chemical EOR agent may displace petroleum from rock in
the
formation or free petroleum trapped in pores in the rock in the formation by
reducing
interfacial surface tension between petroleum and injected water to very low
values
thereby allowing trapped petroleum droplets to deform and flow through rock
pores to
form an oil bank. Polymer may be used to raise the viscosity of water to force
the formed
oil bank to a production well for recovery.
Relatively new EOR methods include injecting chemical solvents into a
petroleum-
bearing formation to mobilize the petroleum for recovery from the formation.
Petroleum
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in the formation is at least partially soluble in such solvents, which
typically have
substantially lower viscosity than the petroleum. The petroleum and chemical
solvent may
mix in the formation in a manner similar to a gaseous miscible EOR agent,
lowering the
viscosity of the petroleum, reducing the surface tension of the petroleum, and
swelling the
petroleum, thereby mobilizing the petroleum for production from the formation.
Chemical
solvents that have been utilized for this purpose include carbon disulfide and
dimethyl
ether.
Improvements to existing chemical solvent EOR methods are desirable. For
example, chemical solvent EOR methods that increase petroleum recovery from a
formation while minimizing reservoir souring, loss of EOR agent due to its
solubility in
formation water, and eliminate formation clean-up required as a result of the
toxicity of the
EOR formulation are desired.
Summary of the Invention
In one aspect, the present invention is directed to method for recovering
petroleum,
comprising:
providing an oil recovery formulation comprising at least 75 mol % dimethyl
sulfide;
introducing the oil recovery formulation into a subterranean petroleum-bearing
formation comprised of a material selected from the group consisting of a
porous mineral
matrix, a porous rock matrix, and a combination of a porous mineral matrix and
a porous
rock matrix;
contacting the oil recovery formulation with petroleum in the petroleum-
bearing
formation; and
producing petroleum from the formation after introduction of the oil recovery
formulation into the formation.
In another aspect, the present invention is directed to a system comprising:
an oil recovery formulation comprising at least 75 mol % dimethyl sulfide;
a subterranean petroleum-bearing formation comprised of a material selected
from
the group consisting of a porous mineral matrix, a porous rock matrix, and a
combination
of a porous mineral matrix and a porous rock matrix;
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a mechanism for introducing the oil recovery formulation into the subterranean
petroleum-bearing formation; and
a mechanism for producing petroleum from the subterranean petroleum-bearing
formation subsequent to the introduction of the oil recovery formulation into
the formation.
Brief Description of the Drawings
The drawing figures depict one or more implementations in accord with the
present
teachings, by way of example only, not by way of limitation. In the figures,
like reference
numerals refer to the same or similar elements.
Fig. 1 is an illustration of a petroleum production system in accordance with
the present
invention.
Fig. 2 is an illustration of a petroleum production system in accordance with
the present
invention.
Fig. 3 is an illustration of a petroleum production system in accordance with
the present
invention.
Fig. 4 is a diagram of a well pattern for production of petroleum in
accordance with a
system and process of the present invention.
Fig. 5. is a diagram of a well pattern for production of petroleum in
accordance with a
system and process of the present invention.
Fig. 6 is a graph showing petroleum recovery from oil sands at 30 C using
various
solvents.
Fig. 7 is a graph showing petroleum recovery from oil sands at 10 C using
various
solvents.
Fig. 8 is a graph showing the viscosity reducing effect of increasing
concentrations of
dimethyl sulfide on a West African Waxy crude oil.
Fig. 9 is a graph showing the viscosity reducing effect of increasing
concentrations of
dimethyl sulfide on a Middle Eastern Asphaltic crude oil.
Fig. 10 is a graph showing the viscosity reducing effect of increasing
concentrations of
dimethyl sulfide on a Canadian Asaphaltic crude oil.
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Detailed Description of the Invention
The present invention is directed to a method and system for enhanced oil
recovery
from a subterranean petroleum-bearing formation utilizing an oil recovery
formulation
comprising at least 75 mol % dimethyl sulfide. The oil recovery formulation
may be first
contact miscible with petroleum in the subterranean formation so that upon
introduction
into the formation the oil recovery formulation may completely mix with the
petroleum it
contacts in the formation. The oil recovery formulation may have a very low
viscosity so
that upon mixing with the petroleum it contacts in the subterranean formation
a mixture of
the petroleum and the oil recovery formulation may be produced having a
significantly
reduced viscosity relative to the petroleum initially in place in the
formation. The mixture
of petroleum and oil recovery formulation may be mobilized for movement
through the
subterranean formation, in part due to the reduced viscosity of the mixture
relative to the
petroleum initially in place in the formation, where the mobilized mixture may
be
produced from the formation, thereby producing petroleum from the formation.
Certain terms used herein are defined as follows:
"Asphaltenes", as used herein, are defined as hydrocarbons that are insoluble
in n-heptane
and soluble in toluene at standard temperature and pressure.
"Miscible", as used herein, is defined as the capacity of two or more
substances,
compositions, or liquids to be mixed in any ratio without separation into two
or more
phases.
"Fluidly operatively coupled or fluidly operatively connected", as used
herein, defines a
connection between two or more elements in which the elements are directly or
indirectly
connected to allow direct or indirect fluid flow between the elements. The
term "fluid
flow", as used herein, refers to the flow of a gas or a liquid.
"Petroleum", as used herein, is defined as a naturally occurring mixture of
hydrocarbons,
generally in a liquid state, which may also include compounds of sulfur,
nitrogen, oxygen,
and metals.
"Residue", as used herein, refers to petroleum components that have a boiling
range
distribution above 538 C (1000 F) at 0.101 MPa, as determined by ASTM Method
D7169
The oil recovery formulation provided for use in the method or system of the
present invention is comprised of at least 75 mol % dimethyl sulfide. The oil
recovery
formulation may be comprised of at least 80 mol %, or at least 85 mol %, or at
least 90 mol
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%, or at least 95 mol %, or at least 97 mol %, or at least 99 mol % dimethyl
sulfide. The
oil recovery formulation may be comprised of at least 75 vol.%, or at least 80
vol.%, or at
least 85 vol.%, or at least 90 vol.%, or at least 95 vol.%, or at least 97
vol.%, or at least 99
vol.% dimethyl sulfide. The oil recovery formulation may be comprised of at
least 75
wt.%, or at least 80 wt.%, or at least 85 wt.%, or at least 90 wt.%, or at
least 95 wt.%, or at
least 97 wt.%, or at least 99 wt.% dimethyl sulfide. The oil recovery
formulation may
consist essentially of dimethyl sulfide, or may consist of dimethyl sulfide.
The oil recovery formulation provided for use in the method or system of the
present invention may be comprised of one or more co-solvents that form a
mixture with
the dimethyl sulfide in the oil recovery formulation. The one or more co-
solvents are
preferably miscible with dimethyl sulfide. The one or more co-solvents may be
selected
from the group consisting of o-xylene, toluene, carbon disulfide,
dichloromethane,
trichloromethane, C3-C8 aliphatic and aromatic hydrocarbons, natural gas
condensates,
hydrogen sulfide, diesel, kerosene, dimethyl ether, and mixtures thereof.
The oil recovery formulation provided for use in the method or system of the
present invention may be first contact miscible with liquid phase petroleum
compositions,
preferably any liquid phase petroleum composition. In liquid phase or in gas
phase the oil
recovery formulation may be first contact miscible with liquid petroleum
compositions
including heavy crude oils, intermediate crude oils, and light crude oils, and
may be first
contact miscible in liquid phase or in gas phase with the petroleum in the
subterranean
petroleum-bearing formation. The oil recovery formulation may be first contact
miscible
with a hydrocarbon composition, for example a liquid phase crude oil, that
comprises at
least 25 wt.%, or at least 30 wt.%, or at least 35 wt.%, or at least 40 wt.%
hydrocarbons
that have a boiling point of at least 538 C (1000 F) as determined by ASTM
Method
D7169. The oil recovery formulation may be first contact miscible with liquid
phase
residue and liquid phase asphaltenes in a hydrocarbonaceous composition, for
example a
crude oil. The oil recovery formulation may be first contact miscible with a
hydrocarbon
composition that comprises less than 25 wt.%, or less than 20 wt.%, or less
than 15 wt.%,
or less than 10 wt.%, or less than 5 wt.% of hydrocarbons having a boiling
point of at least
538 C (1000 F) as determined by ASTM Method D7169. The oil recovery
formulation
may be first contact miscible with C3 to C8 aliphatic and aromatic
hydrocarbons containing
less than 5 wt.% oxygen, less than 10 wt.% sulfur, and less than 5 wt.%
nitrogen.
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The oil recovery formulation may be first contact miscible with hydrocarbon
compositions, for example a crude oil or liquid phase petroleum, over a wide
range of
viscosities. The oil recovery formulation may be first contact miscible with a
hydrocarbon
composition having a low or moderately low viscosity. The oil recovery
formulation may
be first contact miscible with a hydrocarbon composition, for example a liquid
phase
petroleum, having a dynamic viscosity of at most 1000 mPa s (1000 cP), or at
most 500
mPa s (500 cP), or at most 100 mPa s (100 cP) at 25 C. The oil recovery
formulation may
also be first contact miscible with a hydrocarbon composition having a
moderately high or
a high viscosity. The oil recovery formulation may be first contact miscible
with a
hydrocarbon composition, for example a liquid phase petroleum, having a
dynamic
viscosity of at least 1000 mPa s (1000 cP), or at least 5000 mPa s (5000 cP),
or at least
10000 mPa s (10000 cP), or at least 50000 mPa s (50000 cP), or at least 100000
mPa s
(100000 cP), or at least 500000 mPa s (500000 cP) at 25 C. The oil recovery
formulation
may be first contact miscible with hydrocarbon composition, for example a
liquid phase
petroleum, having a dynamic viscosity of from 1 mPa s (1 cP) to 5000000 mPa s
(5000000
cP), or from 100 mPa s (100 cP) to 1000000 mPa s (1000000 cP), or from 500 mPa
s (500
cP) to 500000 mPa s (500000 cP), or from 1000 mPa s (1000 cP) to 100000 mPa s
(100000
cP) at 25 C.
The oil recovery formulation provided for use in the method or system of the
present invention preferably has a low viscosity. The oil recovery formulation
may be a
fluid having a dynamic viscosity of at most 0.35 mPa s (0.35 cP), or at most
0.3 mPa s (0.3
cP), or at most 0.285 mPa s (0.285 cP) at a temperature of 25 C.
The oil recovery formulation provided for use in the method or system of the
present invention preferably has a relatively low density. The oil recovery
formulation
may have a density of at most 0.9 g/cm3, or at most 0.85 g/cm3.
The oil recovery formulation provided for use in the method or system of the
present invention may have a relatively high cohesive energy density. The oil
recovery
formulation provided for use in the method or system of the present invention
may have a
cohesive energy density of from 300 Pa to 410 Pa, or from 320 Pa to 400 Pa.
The oil recovery formulation provided for use in the method or system of the
present invention preferably is relatively non-toxic or is non-toxic. The oil
recovery
formulation may have an aquatic toxicity of LC50 (rainbow trout) greater than
200 mg/1 at
96 hours. The oil recovery formulation may have an acute oral toxicity of LD50
(mouse
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and rat) of from 535 mg/kg to 3700 mg/kg, an acute dermal toxicity of LD50
(rabbit) of
greater 5000 mg/kg, and an acute inhalation toxicity of LC50 (rat) of 40250
ppm at 4 hours.
In the method of the present invention the oil recovery formulation is
introduced
into a subterranean petroleum-bearing formation, and the system of the present
invention
includes a subterranean petroleum-bearing formation. The subterranean
petroleum-bearing
formation comprises petroleum that may be separated and produced from the
formation
after contact and mixing with the oil recovery formulation. The petroleum of
the
subterranean petroleum-bearing formation may be first contact miscible with
the oil
recovery formulation. The petroleum of the subterranean petroleum-bearing
formation
may be a heavy oil containing at least 25 wt.%, or at least 30 wt.%, or at
least 35 wt.%, or
at least 40 wt.% of hydrocarbons having a boiling point of at least 538 C
(1000 F) as
determined in accordance with ASTM Method D7169. The heavy oil may contain at
least
wt.% residue, or at least 25 wt.% residue, or at least 30 wt.% residue. The
heavy oil
may have an asphaltene content of at least at least 5 wt.%, or at least 10
wt.%, or at least 15
15 wt.%.
The petroleum contained in the subterranean petroleum-bearing formation may be
an intermediate weight oil or a relatively light oil containing less than 25
wt.%, or less than
20 wt.%, or less than 15 wt.%, or less than 10 wt.%, or less than 5 wt.% of
hydrocarbons
having a boiling point of at least 538 C (1000 F). The intermediate weight oil
or light oil
20 may have an asphaltenes content of less than 5 wt.%.
The petroleum contained in the subterranean petroleum-bearing formation may
have a viscosity under formation conditions (in particular, at temperatures
within the
temperature range of the formation) of at least 1 mPa s (1 cP), or at least 10
mPa s (10 cP),
or at least 100 mPa s (100 cP), or at least 1000 mPa s (1000 cP), or at least
10000 mPa s
(10000 cP). The petroleum contained in the subterranean petroleum-bearing
formation
may have a viscosity under formation temperature conditions of from 1 to
10000000 mPa s
(1 to 10000000 cP). In an embodiment, the petroleum contained in the
subterranean
petroleum-bearing formation may have a viscosity under formation temperature
conditions
of at least 1000 mPa s (1000 cP), where the viscosity of the petroleum is at
least partially,
or solely, responsible for immobilizing the petroleum in the formation.
The petroleum contained in the subterranean petroleum-bearing formation may
contain little or no microcrystalline wax at formation temperature conditions.
Microcrystalline wax is a solid that may be only partially soluble, or may be
substantially
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insoluble, in the oil recovery formulation. The petroleum contained in the
subterranean
petroleum-bearing formation may comprise at most 3 wt.%, or at most 1 wt.%, or
at most
0.5 wt.% microcrystalline wax at formation temperature conditions, and
preferably
microcrystalline wax is absent from the petroleum in the petroleum-bearing
formation at
formation temperature conditions.
The petroleum-bearing formation is a subterranean formation. The subterranean
formation is comprised of one or more porous matrix materials selected from
the group
consisting of a porous mineral matrix, a porous rock matrix, and a combination
of a porous
mineral matrix and a porous rock matrix, where the porous matrix material may
be located
beneath an overburden at a depth ranging from 50 meters to 6000 meters, or
from 100
meters to 4000 meters, or from 200 meters to 2000 meters under the earth's
surface. The
subterranean formation may be a subsea formation or a subsurface formation.
The porous matrix material may be a consolidated matrix material in which at
least
a majority, and preferably substantially all, of the rock and/or mineral that
forms the matrix
material is consolidated such that the rock and/or mineral forms a mass in
which
substantially all of the rock and/or mineral is immobile when petroleum, the
oil recovery
formulation, water, or other fluid is passed therethrough. Preferably at least
95 wt.% or at
least 97 wt.%, or at least 99 wt.% of the rock and/or mineral is immobile when
petroleum,
the oil recovery formulation, water, or other fluid is passed therethrough so
that any
amount of rock or mineral material dislodged by the passage of the petroleum,
oil recovery
formulation, water, or other fluid is insufficient to render the formation
impermeable to the
flow of the oil recovery formulation, petroleum, water, or other fluid through
the
formation. The porous matrix material may be an unconsolidated matrix material
in which
at least a majority, or substantially all, of the rock and/or mineral that
forms the matrix
material is unconsolidated. The formation may have a permeability of from
0.0001 to 15
Darcies, or from 0.001 to 1 Darcy. The rock and/or mineral porous matrix
material of the
formation may be comprised of sandstone and/or a carbonate selected from
dolomite,
limestone, and mixtures thereof¨where the limestone may be microcrystalline or
crystalline limestone and/or chalk.
Petroleum in the subterranean petroleum-bearing formation may be located in
pores within the porous matrix material of the formation. The petroleum in the
subterranean petroleum-bearing formation may be immobilized in the pores
within the
porous matrix material of the formation, for example, by capillary forces, by
interaction of
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the petroleum with the pore surfaces, by the viscosity of the petroleum, or by
interfacial
tension between the petroleum and water in the formation.
The subterranean petroleum-bearing formation may also be comprised of water,
which may be located in pores within the porous matrix material. The water in
the
formation may be connate water, water from a secondary or tertiary oil
recovery process
water-flood, or a mixture thereof. The water in the subterranean petroleum-
bearing
formation may be positioned to immobilize petroleum within the pores. Contact
of the oil
recovery formulation with the petroleum in the subterranean formation may
mobilize the
petroleum in the formation for production and recovery from the formation by
freeing at
least a portion of the petroleum from pores within the formation.
Referring now to Fig. 1, a system 100 of the present invention is shown for
practicing a method of the present invention. An oil recovery formulation as
described
above may be provided in an oil recovery formulation storage facility 101
fluidly
operatively coupled to an injection/production facility 103 via conduit 105.
Injection/production facility 103 may be fluidly operatively coupled to a well
107, which
may be located extending from the injection/production facility 103 into a
subterranean
petroleum-bearing formation 109 such as described above comprised of one or
more
formation portions 111, 113, and 115 formed of porous material matrices, such
as
described above, located beneath an overburden 117. As shown by the down arrow
in well
107, the oil recovery formulation may flow from the injection/production
facility 103
through the well to be introduced into the formation 109, for example in
formation portion
113, where the injection/production facility 103 and the well 107, or the well
107 itself,
include(s) a mechanism for introducing the oil recovery formulation into the
formation
109. The mechanism for introducing the oil recovery formulation into the
formation 109
may be comprised of a pump 110 for delivering the oil recovery formulation to
perforations or openings in the well through which the oil recovery
formulation may be
injected into the formation.
The oil recovery formulation is introduced into the subterranean formation
109, for
example by being injected into the formation by pumping the oil recovery
formulation into
the formation. The oil recovery formulation may be introduced into the
formation at a
pressure above the instantaneous pressure in the formation to force the oil
recovery
formulation to flow into the formation. The pressure at which the oil recovery
formulation
is introduced into the formation may range from the instantaneous pressure in
the
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formation up to, but not including, the fracture pressure of the formation.
The pressure at
which the oil recovery formulation may be injected into the formation may
range from
20% to 95%, or from 40% to 90%, of the fracture pressure of the formation. The
pressure
at which the oil recovery formulation is injected into the formation may range
from a
pressure from greater than 0 MPa to 37 MPa above the initial formation
pressure as
measured prior to when the injection begins.
An amount of the oil recovery formulation may be introduced into the formation
to
form a mobilized mixture of petroleum and the oil recovery formulation. The
amount of
oil recovery formulation introduced into the formation may be sufficient to
form a
mobilized mixture of the oil recovery formulation and petroleum that may
contain at least
10 vol.%, or at least 20 vol.%, or at least 30 vol.%, or at least 40 vol.%, or
at least 50
vol.%, or greater than 50 vol.% of the oil recovery formulation.
As the oil recovery formulation is introduced into the subterranean formation
109,
the oil recovery formulation spreads into the formation as shown by arrows
119. Upon
introduction to the formation 109, the oil recovery formulation contacts and
forms a
mixture with a portion of the petroleum in the formation. The oil recovery
formulation is
first contact miscible with the petroleum in the formation, where the oil
recovery
formulation mobilizes at least a portion of the petroleum in the formation
upon mixing
with the petroleum. The oil recovery formulation may mobilize the petroleum in
the
formation upon mixing with the petroleum, for example, by reducing the
viscosity of the
mixture relative to the native petroleum in the formation, by reducing the
capillary forces
retaining the petroleum in pores in the formation, by reducing the wettability
of the
petroleum on pore surfaces in the formation, by reducing the interfacial
tension between
petroleum and water in the pores in the formation, and/or by swelling the
petroleum in the
pores in the formation.
The respective viscosities of the oil recovery formulation and water in the
subterranean formation may be on the same order of magnitude, thereby
providing for a
favorable displacement of the water from pores of the formation by the oil
recovery
formulation and corresponding ingress of the oil recovery formulation into the
pores of the
formation for mixing with petroleum contained in the pores. For example, the
viscosity of
the oil recovery formulation may range between about 0.2 cP and about 0.35 cP
under
formation temperature conditions. The viscosity of water of the formation may
range
between about 0.7 cP and about 1.1 cP under formation temperature conditions.
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result, the oil recovery formulation is able to push the water out of the way
and
simultaneously contact, mix, and mobilize the petroleum.
The oil recovery formulation may be left to soak in the subterranean formation
after
introduction of the oil recovery formulation into the formation to mix with
and mobilize
the petroleum in the formation. The oil recovery formulation may be left to
soak in the
formation for a period of time of from 1 hour to 15 days, preferably from 5
hours to 50
hours.
Subsequent to the introduction of the oil recovery formulation into the
subterranean
formation 109 and after the soaking period, petroleum may be recovered and
produced
from the formation 109, as shown in Fig. 2. Optionally oil recovery
formulation¨
preferably in a mixture with the petroleum¨is also recovered and produced from
the
subterranean formation 109, and optionally gas and water from the formation
are also
recovered and produced from the formation 109. The system includes a mechanism
for
producing the petroleum, and may include a mechanism for producing the oil
recovery
formulation, gas, and water from the formation 109 subsequent to introduction
of the oil
recovery formulation into the formation, for example, after completion of
introduction of
the oil recovery formulation into the formation. The mechanism for recovering
and
producing the petroleum, and optionally the oil recovery formulation, gas, and
water from
the formation 109 may be comprised of a pump 112, which may be located in the
injection/production facility 103 and/or within the well 107, and which draws
the
petroleum, and optionally the oil recovery formulation, gas, and water from
the formation
to deliver the petroleum, and optionally the oil recovery formulation, gas,
and water, to the
facility 103.
Alternatively, the mechanism for recovering and producing the petroleum and
the
oil recovery formulation, and optionally gas and water, from the formation 109
may be
comprised of a compressor 114. The compressor 114 may be fluidly operatively
coupled
to a gas storage tank 129 by conduit 116, and may compress gas from the gas
storage tank
for injection into the formation though the well 107. The compressor 114 may
compress
gas from a gas storage tank for injection into the formation 109 through the
well 107. The
compressor may compress the gas to a pressure sufficient to drive production
of petroleum
and the oil recovery formulation, and optionally gas and water, from the
formation via the
well 107, where the appropriate pressure can be determined by conventional
methods
known to those skilled in the art. The compressed gas may be injected into the
formation
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from a different position on the well 107 than the well position at which the
petroleum and
optionally the oil recovery formulation, water and/or gas, are produced from
the
formation, for example, the compressed gas may be injected into the formation
at
formation portion 111 while petroleum, oil recovery formulation, water, and
gas are
produced from the formation at formation portion 113.
Petroleum, preferably in a mixture with the oil recovery formulation, and
optionally
mixed with water and formation gas may be drawn from the formation portion 113
as
shown by arrows 121 and produced back up the well 107 to the
injection/production
facility 103. The petroleum may be separated from the oil recovery
formulation, water,
and gas in a separation unit 123. The separation unit may be comprised of a
conventional
liquid-gas separator for separating gas from the petroleum, oil recovery
formulation, and
water, a conventional hydrocarbon-water separator for separating water from
petroleum
and the oil recovery formulation, and a conventional distillation column for
separating the
oil recovery formulation from the petroleum. For ease of separation of the
produced oil
recovery formulation from the produced petroleum, the produced oil recovery
formulation
may be separated from the petroleum by distillation so that the produced oil
recovery
formulation contains C3 to C8, or C3 to C6, aliphatic and aromatic
hydrocarbons originating
from the petroleum produced from the formation and not present in the initial
oil recovery
formulation. The distillation may be effected so the produced oil recovery
formulation has
the composition of the original oil recovery formulation plus up to 25 vol.%
of C3 to C8
aliphatic and aromatic hydrocarbons derived from the formation, where the
separated
produced oil recovery formulation is comprised of at least 75 mol % dimethyl
sulfide.
The separated petroleum may be provided from the separation unit 123 of the
injection/production facility 103 to a liquid storage tank 125, which may be
fluidly
operatively coupled to the separation unit of the injection/production
facility by conduit
127. The separated gas may be provided from the separation unit 123 of the
injection/production facility 103 to the gas storage tank 129, which may be
fluidly
operatively coupled to the separation unit of the injection/production
facility by conduit
131.
The separated produced oil recovery formulation, optionally containing
additional
C3 to C8 or C3 to C6 hydrocarbons, may be provided from the separation unit
123 of the
injection/production facility to the oil recovery formulation storage facility
101, which may
be fluidly operatively coupled to the separation unit of the
injection/production facility by
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conduit 133. Alternatively, the separated produced oil recovery formulation,
optionally
containing additional C3 to C8 or C3 to C6 hydrocarbons, may be provided from
the
separation unit 123 of the injection/production facility 103 to the injection
mechanism 110
for reinjection into the formation, where the separation unit 123 may be
fluidly operatively
coupled to the injection mechanism 110 via conduit 118 to provide the
separated produced
oil recovery formulation from the separation unit 123 to the injection
mechanism.
Separated water may be provided from the separation unit 123 of the
injection/production facility 103 to a water tank 135, which may be fluidly
operatively
coupled to the separation unit of the injection/production facility by conduit
137. The
water tank 135 may be fluidly operatively coupled to the injection mechanism
110 by
conduit 139 for re-injection of water produced from the formation back into
the
subterranean formation.
After recovery and production of at least a portion of the petroleum from the
subterranean formation 109, and optionally recovering and producing at least a
portion of
the oil recovery formulation injected into the formation, an additional
portion of the oil
recovery formulation may be injected into the formation to mobilize at least a
portion of
the petroleum remaining in the formation for recovery and production. The
amount of the
additional portion of oil recovery formulation injected into the formation 109
may be
increased relative to the amount of oil recovery formulation injected prior to
the injection
of the additional portion of oil recovery formulation to increase the pore
volume of the
formation that is contacted by the oil recovery formulation. An additional
portion of the
petroleum remaining in the formation may be mobilized, recovered, and produced
from the
well subsequent to injection of the additional portion of the oil recovery
formulation in a
manner as described above. Subsequent additional portions of oil recovery
formulation
may be injected into the formation for further recovery and production of
petroleum from
the formation 109, as desired.
Referring now to Fig. 3, a system 200 of the present invention for practicing
a
method of the present invention is shown. The system includes a first well 201
and a
second well 203 extending into a subterranean petroleum-bearing formation 205
such as
described above. The subterranean petroleum-bearing formation 205 may be
comprised of
one or more formation portions 207, 209, and 211 formed of porous material
matrices,
such as described above, located beneath an overburden 213. An oil recovery
formulation
as described above is provided. The oil recovery formulation may be provided
from an oil
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recovery formulation storage facility 215 fluidly operatively coupled to a
first
injection/production facility 217 via conduit 219. First injection/production
facility 217
may be fluidly operatively coupled to the first well 201, which may be located
extending
from the first injection/production facility 217 into the subterranean
petroleum-bearing
formation 205. The oil recovery formulation may flow from the first
injection/production
facility 217 through the first well to be introduced into the subterranean
formation 205, for
example in formation portion 209, where the first injection/production
facility 217 and the
first well, or the first well itself, include(s) a mechanism for introducing
the oil recovery
formulation into the formation. Alternatively, the oil recovery formulation
may flow from
the oil recovery formulation storage facility 215 directly to the first well
201 for injection
into the formation 205, where the first well comprises a mechanism for
introducing the oil
recovery formulation into the formation. The mechanism for introducing the oil
recovery
formulation into the subterranean formation 205 via the first well 201¨located
in the first
injection/production facility 217, the first well 201, or both¨may be
comprised of a pump
221 for delivering the oil recovery formulation to perforations or openings in
the first well
through which the oil recovery formulation may be introduced into the
formation.
The oil recovery formulation may be introduced into the subterranean formation
205, for example by injecting the oil recovery formulation into the formation
through the
first well 201 by pumping the oil recovery formulation through the first well
and into the
formation. The pressure at which the oil recovery formulation may be injected
into the
subterranean formation 205 through the first well 201 may be as described
above with
respect to injection and production using a single well.
The volume of oil recovery formulation introduced into the subterranean
formation
205 via the first well 201 may range from 0.001 to 5 pore volumes, or from
0.01 to 2 pore
volumes, or from 0.1 to 1 pore volumes, or from 0.2 to 0.6 pore volumes, where
the term
"pore volume" refers to the volume of the formation that may be swept by the
oil recovery
formulation between the first well 201 and the second well 203. The pore
volume may be
readily be determined by methods known to a person skilled in the art, for
example by
modelling studies or by injecting water having a tracer contained therein
through the
formation 205 from the first well 201 to the second well 203.
As the oil recovery formulation is introduced into the subterranean formation
205,
the oil recovery formulation spreads into the formation as shown by arrows
223. Upon
introduction to the formation 205, the oil recovery formulation contacts and
forms a
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mixture with a portion of the petroleum in the formation. The oil recovery
formulation is
first contact miscible with the petroleum in the subterranean formation 205,
where the oil
recovery formulation may mobilize the petroleum in the formation upon
contacting and
mixing with the petroleum. The oil recovery formulation may mobilize the
petroleum in
the formation upon contacting and mixing with the petroleum, for example, by
reducing
the viscosity of the mixture relative to the native petroleum in the
formation, by reducing
the capillary forces retaining the petroleum in pores in the formation, by
reducing the
wettability of the petroleum on pore surfaces in the formation, by reducing
the interfacial
tension between petroleum and water in the pores in the formation, and/or by
swelling the
petroleum in the pores in the formation. As noted above, the oil recovery
formulation may
have a viscosity on the same order of magnitude as the viscosity of water in
the formation
at formation temperature conditions enabling the oil recovery formation to
displace water
from pores of the formation to penetrate the pores and contact, mix with, and
mobilize
petroleum contained therein.
The mobilized mixture of the oil recovery formulation and petroleum and any
unmixed oil recovery formulation may be pushed across the subterranean
formation 205
from the first well 201 to the second well 203 by further introduction of more
oil recovery
formulation or by introduction of an oil immiscible formulation into the
formation
subsequent to introduction of the oil recovery formulation into the formation.
The oil
immiscible formulation may be introduced into the subterranean formation 205
through the
first well 201 after completion of introduction of the oil recovery
formulation into the
formation to force or otherwise displace the mobilized mixture of the oil
recovery
formulation and petroleum as well as any unmixed oil recovery formulation
toward the
second well 203 for production. Any unmixed oil recovery formulation may mix
with and
mobilize more petroleum in the formation 205 as the unmixed oil recovery
formulation is
displaced through the formation from the first well 201 towards the second
well 203.
The oil immiscible formulation may be configured to displace the mobilized
mixture of oil recovery formulation and petroleum as well as any unmixed oil
recovery
formulation through the formation 205. Suitable oil immiscible formulations
are not first
contact miscible or multiple contact miscible with petroleum in the
subterranean formation
205. The oil immiscible formulation may be selected from the group consisting
of an
aqueous polymer fluid, water in gas or liquid form, carbon dioxide at a
pressure below its
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minimum miscibility pressure, nitrogen at a pressure below its minimum
miscibility
pressure, air, and mixtures of two or more of the preceding.
Suitable polymers for use in an aqueous polymer fluid may include, but are not
limited to, polyacrylamides, partially hydrolyzed polyacrylamides,
polyacrylates, ethylenic
copolymers, biopolymers, carboxymethylcellulose, polyvinyl alcohols,
polystyrene
sulfonates, polyvinylpyrolidones, AMPS (2-acrylamide-2-methyl propane
sulfonate),
combinations thereof, or the like. Examples of ethylenic copolymers include
copolymers
of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, lauryl
acrylate and
acrylamide. Examples of biopolymers include xanthan gum, guar gum, alginates,
and
alginic acids and salts thereof. In some embodiments, polymers may be
crosslinked in situ
in the subterranean formation 205. In other embodiments, polymers may be
generated in
situ in the subterranean formation 205.
The oil immiscible formulation may be stored in, and provided for introduction
into
the subterranean formation 205 from, an oil immiscible formulation storage
facility 225
that may be fluidly operatively coupled to the first injection/production
facility 217 via
conduit 227. The first injection/production facility 217 may be fluidly
operatively coupled
to the first well 201 to provide the oil immiscible formulation to the first
well for
introduction into the formation 205. Alternatively, the oil immiscible
formulation storage
facility 225 may be fluidly operatively coupled to the first well 201 directly
to provide the
oil immiscible formulation to the first well for introduction into the
formation 205. The
first injection/production facility 217 and the first well 201, or the first
well itself, may
comprise a mechanism for introducing the oil immiscible formulation into the
formation
205 via the first well 201. The mechanism for introducing the oil immiscible
formulation
into the formation 205 via the first well 201 may be comprised of a pump or a
compressor
for delivering the oil immiscible formulation to perforations or openings in
the first well
through which the oil immiscible formulation may be injected into the
formation. The
mechanism for introducing the oil immiscible formulation into the formation
205 via the
first well 201 may be the pump 221 utilized to inject the oil recovery
formulation into the
formation via the first well 201.
The oil immiscible formulation may be introduced into the subterranean
formation
205, for example, by injecting the oil immiscible formulation into the
formation through
the first well 201 by pumping the oil immiscible formulation through the first
well and into
the formation. The pressure at which the oil immiscible formulation may be
injected into
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the subterranean formation 205 through the first well 201 may be up to, but
not including,
the fracture pressure of the formation, or from 20% to 99%, or from 30% to
95%, or from
40% to 90% of the fracture pressure of the formation. In an embodiment of the
present
invention, the oil immiscible formulation may be injected into the
subterranean formation
205 at a pressure from greater than 0 MPa to 37 MPa above the formation
pressure as
measured prior to injection of the oil immiscible formulation.
The amount of oil immiscible formulation introduced into the subterranean
formation 205 via the first well 201 following introduction of the oil
recovery formulation
into the formation via the first well may range from 0.001 to 5 pore volumes,
or from 0.01
to 2 pore volumes, or from 0.1 to 1 pore volumes, or from 0.2 to 0.6 pore
volumes, where
the term "pore volume" refers to the volume of the formation that may be swept
by the oil
immiscible formulation between the first well and the second well. The amount
of oil
immiscible formulation introduced into the formation 205 should be sufficient
to drive the
mobilized petroleum/oil recovery formulation mixture and any unmixed oil
recovery
formulation across at least a portion of the formation. If the oil immiscible
formulation is
in liquid phase, the volume of oil immiscible formulation introduced into the
subterranean
formation 205 following introduction of the oil recovery formulation into the
formation
relative to the volume of oil recovery formulation introduced into the
formation
immediately preceding introduction of the oil immiscible formulation may range
from
0.1:1 to 10:1 of oil immiscible formulation to oil recovery formulation, more
preferably
from 1:1 to 5:1 of oil immiscible formulation to oil recovery formulation. If
the oil
immiscible formulation is in gaseous phase, the volume of oil immiscible
formulation
introduced into the formation 205 following introduction of the oil recovery
formulation
into the formation relative to the volume of oil recovery formulation
introduced into the
formation immediately preceding introduction of the oil immiscible formulation
may be
substantially greater than a liquid phase oil immiscible formulation, for
example, at least
10 or at least 20, or at least 50 volumes of gaseous phase oil immiscible
formulation per
volume of oil recovery formulation introduced immediately preceding
introduction of the
gaseous phase oil immiscible formulation.
If the oil immiscible formulation is in liquid phase, the oil immiscible
formulation
may have a viscosity of at least the same magnitude as the viscosity of the
mobilized
petroleum/oil recovery formulation mixture at formation temperature conditions
to enable
the oil immiscible formulation to drive the mixture of mobilized petroleum/oil
recovery
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formulation across the formation 205 to the second well 203. The oil
immiscible
formulation may have a viscosity of at least 0.8 mPa s (0.8 cP) or at least 10
mPa s (10 cP),
or at least 50 mPa s (50 cP), or at least 100 mPa s (100 cP), or at least 500
mPa s (500 cP),
or at least 1000 mPa s (1000 cP) at formation temperature conditions or at 25
C. If the oil
immiscible formulation is in liquid phase, preferably the oil immiscible
formulation has a
viscosity at least one order of magnitude greater than the viscosity of the
mobilized
petroleum/oil recovery formulation mixture at formation temperature conditions
so the oil
immiscible formulation may drive the mobilized petroleum/oil recovery
formulation
mixture across the formation in plug flow, minimizing and inhibiting fingering
of the
mobilized petroleum/oil recovery formulation mixture through the driving plug
of oil
immiscible formulation.
The oil recovery formulation and the oil immiscible formulation may be
introduced
into the formation through the first well 201 in alternating slugs. For
example, the oil
recovery formulation may be introduced into the formation 205 through the
first well 201
for a first time period, after which the oil immiscible formulation may be
introduced into
the formation through the first well for a second time period subsequent to
the first time
period, after which the oil recovery formulation may be introduced into the
formation
through the first well for a third time period subsequent to the second time
period, after
which the oil immiscible formulation may be introduced into the formation
through the
first well for a fourth time period subsequent to the third time period. As
many alternating
slugs of the oil recovery formulation and the oil immiscible formulation may
be introduced
into the formation through the first well as desired.
Petroleum may be mobilized for production from the subterranean formation 205
via the second well 203 by introduction of the oil recovery formulation, and
optionally the
oil immiscible formulation, into the formation, where the mobilized petroleum
is driven
through the formation for production from the second well as indicated by
arrows 229 by
introduction of the oil recovery formulation, and optionally the oil
immiscible formulation,
into the formation via the first well 201. The petroleum mobilized for
production from the
formation 205 may include the mobilized petroleum/oil recovery formulation
mixture.
Water and/or gas may also be mobilized for production from the formation 205
via the
second well 203 by introduction of the oil recovery formulation into the
formation via the
first well 201.
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After introduction of the oil recovery formulation into the subterranean
formation
205 via the first well 201, petroleum may be recovered and produced from the
formation
via the second well 203. The system may include a mechanism located at the
second well
for recovering and producing the petroleum from the subterranean formation 205
subsequent to introduction of the oil recovery formulation into the formation,
and may
include a mechanism located at the second well for recovering and producing
the oil
recovery formulation, the oil immiscible formulation, water, and/or gas from
the formation
subsequent to introduction of the oil recovery formulation into the formation.
The
mechanism located at the second well 203 for recovering and producing the
petroleum, and
optionally for recovering and producing the oil recovery formulation, the oil
immiscible
formulation, water, and/or gas may be comprised of a pump 233, which may be
located in
the second injection/production facility 231 and/or within the second well
203. The pump
233 may draw the petroleum, and optionally the oil recovery formulation, the
oil
immiscible formulation, water, and/or gas from the formation 205 through
perforations in
the second well 203 to deliver the petroleum, and optionally the oil recovery
formulation,
the oil immiscible formulation, water, and/or gas, to the second
injection/production
facility 231.
Alternatively, the mechanism for recovering and producing the petroleum¨and
optionally the oil recovery formulation, the oil immiscible formulation, gas,
and water-
from the formation 205 may be comprised of a compressor 234 that may be
located in the
second injection/production facility 231. The compressor 234 may be fluidly
operatively
coupled to the gas storage tank 241 via conduit 236, and may compress gas from
the gas
storage tank for injection into the formation 205 through the second well 203.
The
compressor may compress the gas to a pressure sufficient to drive production
of
petroleum¨and optionally the oil recovery formulation, the oil immiscible
formulation,
gas, and water¨from the formation via the second well 203, where the
appropriate
pressure may be determined by conventional methods known to those skilled in
the art.
The compressed gas may be injected into the formation from a different
position on the
second well 203 than the well position at which the petroleum¨and optionally
the oil
recovery formulation, the oil immiscible formulation, water, and gas¨are
produced from
the formation, for example, the compressed gas may be injected into the
formation at
formation portion 207 while petroleum, oil recovery formulation, oil
immiscible
formulation, water, and gas are produced from the formation at formation
portion 209.
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Petroleum, optionally in a mixture with the oil recovery formulation, oil
immiscible
formulation, water, and/or gas may be drawn from the subterranean formation
205 as
shown by arrows 229 and produced up the second well 203 to the second
injection/production facility 231. The petroleum may be separated from the oil
recovery
formulation, gas, oil immiscible formulation (if any), and/or water in a
separation unit 235
located in the second injection/production facility 231 and fluidly coupled to
the
mechanism 233 for recovering and producing petroleum and optionally the oil
recovery
formulation, the oil immiscible formulation, gas, and/or water from the
formation. The
separation unit 235 may be comprised of a conventional liquid-gas separator
for separating
gas from the petroleum, oil recovery formulation, liquid oil immiscible
formulation (if
any), and water; a conventional hydrocarbon-water separator for separating the
petroleum
and oil recovery formulation from water and optionally from liquid oil
immiscible
formulation; a conventional distillation column for separating the oil
recovery
formulation¨optionally in combination with C3 to C8, or C3 to C6, aliphatic
and aromatic
hydrocarbons derived from the formation as discussed above¨from the petroleum;
and,
optionally, a separator for separating liquid oil immiscible formulation from
water.
The separated produced petroleum may be provided from the separation unit 235
of
the second injection/production facility 231 to a liquid storage tank 237,
which may be
fluidly operatively coupled to the separation unit 235 of the second
injection/production
facility by conduit 239. The separated gas, if any, may be provided from the
separation
unit 235 of the second injection/production facility 231 to a gas storage tank
241, which
may be fluidly operatively coupled to the separation unit 235 of the second
injection/production facility 231 by conduit 243. Separated water may be
provided from
the separation unit 235 of the second injection/production facility 231 to a
water tank 247,
which may be fluidly operatively coupled to the separation unit 235 of the
second
injection/production facility 231 by conduit 249. Separated oil immiscible
formulation, if
any, may be provided from the separation unit 235 of the second
injection/production
facility 231 to the oil immiscible formulation storage facility 225 by conduit
250.
The separated produced oil recovery formulation, optionally containing
additional
C3 to C8 or C3 to C6 hydrocarbons, may be provided from the separation unit
235 of the
second injection/production facility 231 to the oil recovery formulation
storage unit 215,
which may be fluidly operatively coupled to the separation unit 235 of the
second
injection/production facility 231 by conduit 245, where the produced oil
recovery
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formulation may be mixed with the oil recovery formulation. Alternatively, the
separated
oil recovery formulation may be provided from the separation unit 235 of the
second
injection/production facility 231 to the injection mechanism 221 via conduit
238 for re-
injection into the subterranean formation 205 through the first well 201 for
further
mobilization and production of petroleum from the formation. Alternatively,
the separated
oil recovery formulation may be provided from the separation unit 235 to an
injection
mechanism such as pump 251 in the second injection/production facility 231 via
conduit
240 for re-injection into the subterranean formation 205 through the second
well 203,
optionally together with fresh oil recovery formulation.
In an embodiment of a system and a method of the present invention, the first
well
201 may be used for injecting the oil recovery formulation into the
subterranean formation
205 and the second well 203 may be used to produce petroleum from the
formation as
described above for a first time period, and the second well 203 may be used
for injecting
the oil recovery formulation into the formation 205 to mobilize the petroleum
in the
formation and drive the mobilized petroleum across the formation to the first
well and the
first well 201 may be used to produce petroleum from the formation for a
second time
period, where the second time period is subsequent to the first time period.
The second
injection/production facility 231 may comprise a mechanism such as pump 251
that is
fluidly operatively coupled the oil recovery formulation storage facility 215
by conduit
253, and optionally fluidly operatively coupled to the separation units 235
and 259 by
conduits 240 and 242, respectively, to receive produced oil recovery
formulation
therefrom, and that is fluidly operatively coupled to the second well 203 to
introduce the
oil recovery formulation into the subterranean formation 205 via the second
well. The
pump 251 or a compressor may also be fluidly operatively coupled to the oil
immiscible
formulation storage facility 225 by conduit 255 to introduce the oil
immiscible formulation
into the formation 205 via the second well 203 subsequent to introduction of
the oil
recovery formulation into the formation via the second well. The first
injection/production
facility 217 may comprise a mechanism such as pump 257 or compressor 258 for
production of petroleum, and optionally the oil recovery formulation, the oil
immiscible
formulation, water, and/or gas from the formation 205 via the first well 201.
The first
injection/production facility 217 may also include a separation unit 259 for
separating
petroleum, the oil recovery formulation, the oil immiscible formulation,
water, and/or gas.
The separation unit 259 may be comprised of a conventional liquid-gas
separator for
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separating gas from the petroleum, oil recovery formulation, liquid oil
immiscible
formulation (if any), and water; a conventional hydrocarbon-water separator
for separating
the petroleum and oil recovery formulation from water and optionally from
liquid oil
immiscible formulation; a conventional distillation column for separating the
oil recovery
formulation¨optionally in combination with C3 to C8, or C3 to C6, aliphatic
and aromatic
hydrocarbons derived from the formation¨from the petroleum; and, optionally, a
separator for separating liquid oil immiscible formulation from water. The
separation unit
259 may be fluidly operatively coupled to: the liquid storage tank 237 by
conduit 261 for
storage of produced petroleum in the liquid storage tank; the gas storage tank
241 by
conduit 265 for storage of produced gas in the gas storage tank; and the water
tank 247 by
conduit 267 for storage of produced water in the water tank. Separated oil
immiscible
formulation, if any, may be provided from the separation unit 259 of the first
injection/production facility 217 to the oil immiscible formulation storage
facility 225 by
conduit 268.
The separation unit 259 may be fluidly operatively coupled to the oil recovery
formulation storage facility 215 by conduit 263 for storage of the produced
oil recovery
formulation in the oil recovery formulation storage facility 215. The
separation unit 259
may be fluidly operatively coupled to either the injection mechanism 221 of
the first
injection/production facility 217 for injecting the oil recovery formulation
into the
formation 205 through the first well 201 or the injection mechanism 251 of the
second
injection/production facility 231 for injecting the oil recovery formulation
into the
formation through the second well 203 by conduits 242 and 244, respectively.
The first well 201 may be used for introducing the oil recovery
formulation¨and,
optionally, subsequent to introduction of the oil recovery formulation via the
first well, the
oil immiscible formulation¨into the subterranean formation 205 and the second
well 203
may be used for producing petroleum from the formation for a first time
period; then the
second well 203 may be used for injecting the oil recovery formulation¨and,
optionally,
subsequent to introduction of the oil recovery formulation via the second
well, the oil
immiscible formulation¨into the formation 205 and the first well 201 may be
used for
producing petroleum from the formation for a second time period, where the
first and
second time periods comprise a cycle. Multiple cycles may be conducted which
include
alternating the first well 201 and the second well 203 between introducing the
oil recovery
formulation into the formation 205¨and, optionally introducing the oil
immiscible
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formulation into the formation subsequent to introduction of the oil recovery
formulation¨
and producing petroleum from the formation, where one well is injecting and
the other is
producing for the first time period, and then they are switched for a second
time period. A
cycle may be from about 12 hours to about 1 year, or from about 3 days to
about 6 months,
or from about 5 days to about 3 months. In some embodiments, the oil recovery
formulation may be introduced into the formation at the beginning of a cycle,
and an oil
immiscible formulation may be introduced at the end of the cycle. In some
embodiments,
the beginning of a cycle may be the first 10% to about 80% of a cycle, or the
first 20% to
about 60% of a cycle, the first 25% to about 40% of a cycle, and the end may
be the
remainder of the cycle.
Referring now to Figure 4, an array of wells 300 is illustrated. Array 300
includes
a first well group 302 (denoted by horizontal lines) and a second well group
304 (denoted
by diagonal lines). In some embodiments of the system and method of the
present
invention, the first well of the system and method described above may include
multiple
first wells depicted as the first well group 302 in the array 300, and the
second well of the
system and method described above may include multiple second wells depicted
as the
second well group 304 in the array 300.
Each well in the first well group 302 may be a horizontal distance 330 from an
adjacent well in the first well group 302. The horizontal distance 330 may be
from about 5
to about 1000 meters, or from about 10 to about 500 meters, or from about 20
to about 250
meters, or from about 30 to about 200 meters, or from about 50 to about 150
meters, or
from about 90 to about 120 meters, or about 100 meters. Each well in the first
well group
302 may be a vertical distance 332 from an adjacent well in the first well
group 302. The
vertical distance 332 may be from about 5 to about 1000 meters, or from about
10 to about
500 meters, or from about 20 to about 250 meters, or from about 30 to about
200 meters, or
from about 50 to about 150 meters, or from about 90 to about 120 meters, or
about 100
meters.
Each well in the second well group 304 may be a horizontal distance 336 from
an
adjacent well in the second well group 304. The horizontal distance 336 may be
from
about 5 to about 1000 meters, or from about 10 to about 500 meters, or from
about 20 to
about 250 meters, or from about 30 to about 200 meters, or from about 50 to
about 150
meters, or from about 90 to about 120 meters, or about 100 meters. Each well
in the
second well group 304 may be a vertical distance 338 from an adjacent well in
the second
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well group 304. The vertical distance 338 may be from about 5 to about 1000
meters, or
from about 10 to about 500 meters, or from about 20 to about 250 meters, or
from about 30
to about 200 meters, or from about 50 to about 150 meters, or from about 90 to
about 120
meters, or about 100 meters.
Each well in the first well group 302 may be a distance 334 from the adjacent
wells
in the second well group 304. Each well in the second well group 304 may be a
distance
334 from the adjacent wells in first well group 302. The distance 334 may be
from about 5
to about 1000 meters, or from about 10 to about 500 meters, or from about 20
to about 250
meters, or from about 30 to about 200 meters, or from about 50 to about 150
meters, or
from about 90 to about 120 meters, or about 100 meters.
Each well in the first well group 302 may be surrounded by four wells in the
second
well group 304. Each well in the second well group 304 may be surrounded by
four wells
in the first well group 302.
In some embodiments, the array of wells 300 may have from about 10 to about
1000 wells, for example from about 5 to about 500 wells in the first well
group 302, and
from about 5 to about 500 wells in the second well group 304.
In some embodiments, the array of wells 300 may be seen as a top view with
first
well group 302 and the second well group 304 being vertical wells spaced on a
piece of
land. In some embodiments, the array of wells 300 may be seen as a cross-
sectional side
view of the subterranean formation with the first well group 302 and the
second well group
304 being horizontal wells spaced within the formation.
Referring now to Figure 5, an array of wells 400 is illustrated. Array 400
includes
a first well group 402 (denoted by horizontal lines) and a second well group
404 (denoted
by diagonal lines). The array 400 may be an array of wells as described above
with respect
to array 300 in Figure 4. In some embodiments of the system and method of the
present
invention, the first well of the system and method described above may include
multiple
first wells depicted as the first well group 402 in the array 400, and the
second well of the
system and method described above may include multiple second wells depicted
as the
second well group 404 in the array 400.
The oil recovery formulation may be injected into first well group 402, and
petroleum may be recovered and produced from the second well group 404. As
illustrated,
the oil recovery formulation may have an injection profile 406, and petroleum
may be
produced from the second well group 404 having a petroleum recovery profile
408.
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The oil recovery formulation may be injected into the second well group 404,
and
petroleum may be produced from the first well group 402. As illustrated, the
oil recovery
formulation may have an injection profile 408, and petroleum may be produced
from the
first well group 402 having a petroleum recovery profile 406.
The first well group 402 may be used for injecting the oil recovery
formulation, and
the second well group 404 may be used for producing petroleum from the
formation for a
first time period; then second well group 404 may be used for injecting the
oil recovery
formulation, and the first well group 402 may be used for producing petroleum
from the
formation for a second time period, where the first and second time periods
comprise a
cycle. In some embodiments, multiple cycles may be conducted which include
alternating
first and second well groups 402 and 404 between injecting the oil recovery
formulation,
and producing petroleum and/or gas from the formation, where one well group is
injecting
and the other is producing for a first time period, and then they are switched
for a second
time period.
To facilitate a better understanding of the present invention, the following
examples
of certain aspects of some embodiments are given. In no way should the
following
examples be read to limit, or define, the scope of the invention.
EXAMPLE 1
The quality of dimethyl sulfide as an oil recovery agent based on the
miscibility of
dimethyl sulfide with a crude oil relative to other compounds was evaluated.
The
miscibility of dimethyl sulfide, ethyl acetate, o-xylene, carbon disulfide,
chloroform,
dichloromethane, tetrahydrofuran, and pentane solvents with mined oil sands
was
measured by extracting the oil sands with the solvents at 10 C and at 30 C to
determine the
fraction of hydrocarbons extracted from the oil sands by the solvents. The
bitumen content
of the mined oil sands was measured at 11 wt.% as an average of bitumen
extraction yield
values for solvents known to effectively extract substantially all of bitumen
from oil
sands¨in particular chloroform, dichloromethane, o-xylene, tetrahydrofuran,
and carbon
disulfide. One oil sands sample per solvent per extraction temperature was
prepared for
extraction, where the solvents used for extraction of the oil sands samples
were dimethyl
sulfide, ethyl acetate, o-xylene, carbon disulfide, chloroform,
dichloromethane,
tetrahydrofuran, and pentane. Each oil sands sample was weighed and placed in
a
cellulose extraction thimble that was placed on a porous polyethylene support
disk in a
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jacketed glass cylinder with a drip rate control valve. Each oil sands sample
was then
extracted with a selected solvent at a selected temperature (10 C or 30 C) in
a cyclic
contact and drain experiment, where the contact time ranged from 15 to 60
minutes. Fresh
contacting solvent was applied and the cyclic extraction repeated until the
fluid drained
from the apparatus became pale brown in color.
The extracted fluids were stripped of solvent using a rotary evaporator and
thereafter vacuum dried to remove residual solvent. The recovered bitumen
samples all
had residual solvent present in the range of from 3 wt.% to 7 wt.%. The
residual solids and
extraction thimble were air dried, weighed, and then vacuum dried. Essentially
no weight
loss was observed upon vacuum drying the residual solids, indicating that the
solids did not
retain either extraction solvent or easily mobilized water. Collectively, the
weight of the
solid or sample and thimble recovered after extraction plus the quantity of
bitumen
recovered after extraction divided by the weight of the initial oil sands
sample plus the
thimble provide the mass closure for the extractions. The calculated percent
mass closure
of the samples was slightly high because the recovered bitumen values were not
corrected
for the 3 wt.% to 7 wt.% residual solvent. The extraction experiment results
are
summarized in Table 1.
Table 1
Summary of Extraction Experiments of Bituminous Oil Sands with Various Fluids
Input Output
Experimental
Extraction Fluid Temperature, Solids Solids Weight
Recovered Weight
C weight, weight, Change,
Bitumen, g Closure, %
g g g
Carbon Disulfide 30 151.1 134.74 16.4 16.43 100.0
Carbon Disulfide 10 151.4 134.62 16.8 16.62 99.9
Chloroform 30 153.7 134.3 19.4 18.62 99.5
Chloroform 10 156.2 137.5 18.7 17.85 99.5
Dichloromethane 30 155.8 138.18 17.7 16.30 99.1
Dichloromethane 10 155.2 136.33 18.9 17.66 99.2
o-Xylene 30 156.1 136.58 19.5 17.37 98.6
o-Xylene 10 154.0 136.66 17.3 17.36 100.0
Tetrahydrofuran 30 154.7 136.73 18.0 17.67 99.8
Tetrahydrofuran 10 154.7 136.98 17.7 16.72 99.4
Ethyl Acetate 30 153.5 135.81 17.7 11.46 96.0
Ethyl Acetate 10 155.7 144.51 11.2 10.32 99.4
Pentane 30 154.0 139.11 14.9 13.49 99.1
Pentane 10 152.7 138.65 14.1 13.03 99.3
Dimethyl Sulfide 30 154.2 137.52 16.7 16.29 99.7
Dimethyl Sulfide 10 151.7 134.77 16.9 16.55 99.7
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Fig. 6 provides a graph plotting the weight percent yield of extracted bitumen
as a
function of the extraction fluid at 30 C applied with a correction factor for
residual
extraction fluid in the recovered bitumen, and Fig. 7 provides a similar graph
for extraction
at 10 C without a correction factor. Figs. 6 and 7 and Table 1 show that
dimethyl sulfide is
comparable for recovering bitumen from an oil sand material with the best
known fluids
for recovering bitumen from an oil sand material-o-xylene, chloroform, carbon
disulfide,
dichloromethane, and tetrahydrofuran-and is significantly better than pentane
and ethyl
acetate.
The bitumen samples extracted at 30 C from each oil sands sample were
evaluated
by SARA analysis to determine the saturates, aromatics, resins, and
asphaltenes
composition of the bitumen samples extracted by each solvent. The results are
shown in
Table 2.
Table 2
SARA Analysis of Extracted Bitumen Samples as a Function of Extraction Fluid
Oil Composition Normalized Weight Percent
Extraction Fluid Saturates Aromatics Resins
Asphaltenes
Ethyl Acetate 21.30 53.72 22.92 2.05
Pentane 22.74 54.16 22.74 0.36
Dichloromethane 15.79 44.77 24.98 14.45
Dimethyl Sulfide 15.49 47.07 24.25 13.19
Carbon Disulfide 18.77 41.89 25.49 13.85
o-Xylene 17.37 46.39 22.28 13.96
Tetrahydrofuran 16.11 45.24 24.38 14.27
Chloroform 15.64 43.56 25.94 14.86
The SARA analysis showed that pentane and ethyl acetate were much less
effective
for extraction of asphaltenes from oil sands than are the known highly
effective bitumen
extraction fluids dichloromethane, carbon disulfide, o-xylene,
tetrahydrofuran, and
chloroform. The SARA analysis also showed that dimethyl sulfide has excellent
miscibility properties for even the most difficult hydrocarbons-asphaltenes.
The data showed that dimethyl sulfide is generally as good as the recognized
very
good bitumen extraction fluids for recovery of bitumen from oil sands, and is
highly
compatible with saturates, aromatics, resins, and asphaltenes.
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EXAMPLE 2
The quality of dimethyl sulfide as an oil recovery agent based on the crude
oil
viscosity lowering properties of dimethyl sulfide was evalulated. Three crude
oils having
widely disparate viscosity characteristics-an African Waxy crude, a Middle
Eastern
asphaltic crude, and a Canadian asphaltic crude-were blended with dimethyl
sulfide.
Some properties of the three crudes are provided in Table 3.
Table 3
Crude Oil Properties
African Middle Canadian
Waxy Eastern Asphaltic
crude Asphaltic Crude
crude
Hydrogen (wt.%) 13.21 11.62 10.1
Carbon (wt.%) 86.46 86.55 82
Oxygen (wt.%) na na 0.62
Nitrogen (wt.%) 0.166 0.184 0.37
Sulfur (wt.%) 0.124 1.61 6.69
Nickel (ppm wt.) 32 14.2 70
Vanadium (ppm wt.) 1 11.2 205
microcarbon residue (wt.%) na 8.50 12.5
C5 Asphaltenes (wt.%) <0.1 na 16.2
C7 Asphaltenes (wt.%) <0.1 na 10.9
Density (g/m1) (15.6 C) 0.88 0.9509 1.01
API Gravity (15.6 C) 28.1 17.3 8.5
Water (Karl Fisher Titration) (wt.%) 1.65 <0.1 <0.1
TAN-E (ASTM D664) (mg KOH/g) 1.34 4.5 3.91
Volatiles Removed by Topping, wt% 21.6 0 0
Saturates in Topped Fluid, wt.% 60.4 41.7 12.7
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Aromatics in Topped Fluid, wt.% 31.0 40.5 57.1
Resin in Topped Fluid, wt.% 8.5 14.5 17.1
Asphaltenes in Topped Fluid, wt.% 0.1 3.4 13.1
Boiling Range Distribution
Initial Boiling Point - 204 C (wt.%) 8.5 3.0 0
204 C (400 F) - 260 C (wt.%) 9.5 5.8 1.0
260 C (500 F) - 343 C (wt.%) 16.0 14.0 14.0
343 C (650 F) - 538 C (wt.%) 39.5 42.9 38.0
>538 C (wt.%) 26.5 34.3 47.0
A control sample of each crude was prepared containing no dimethyl sulfide,
and
samples of each crude were prepared and blended with dimethyl sulfide to
prepare crude
samples containing increasing concentrations of dimethyl sulfide. Each sample
of each of
the crudes was heated to 60 C to dissolve any waxes therein and to permit
weighing of a
homogeneous liquid, weighed, allowed to cool overnight, then blended with a
selected
quantity of dimethyl sulfide. The samples of the crude/dimethyl sulfide blend
were then
heated to 60 C and mixed to ensure homogeneous blending of the dimethyl
sulfide in the
samples. Absolute (dynamic) viscosity measurements of each of the samples were
taken
using a rheometer and closed cup sensor assembly. Viscosity measurements of
each of the
samples of the West African waxy crude and the Middle Eastern asphaltic crude
were
taken at 20 C, 40 C, 60 C, 80 C, and then again at 20 C after cooling from 80
C, where the
second measurement at 20 C is taken to measure the viscosity without the
presence of
waxes since wax formation occurs slowly enough to permit viscosity measurement
at 20 C
without the presence of wax. Viscosity measurements of each of the samples of
the
Canadian asphaltic crude were taken at 5 C, 10 C, 20 C, 40 C, 60 C, 80 C, The
measured viscosities for each of the crudes are shown in Tables 4, 5, and 6
below.
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Table 4
Viscosity (mPa s) of West African Waxy Crude vs. Temperature
at Various levels of Dimethyl Sulfide Diluent
DMS, wt.% 20 C 40 C 60 C 80 C 20 C
0.00 128.8 34.94 15.84 9.59 114.4
1.21 125.8 30.94 14.66 8.92 100.1
2.48 122.3 30.53 13.66 8.44 89.23
5.03 78.37 20.24 10.45 6.55 55.21
7.60 60.92 17.08 9.29 6.09 40.89
9.95 44.70 13.03 7.58 5.04 30.61
15.13 23.96 8.32 4.97 3.38 17.64
19.30 15.26 6.25 4.05 2.92 12.06
Table 5
Viscosity (mPa s) of Middle Eastern Asphaltic Crude vs. Temperature
at Various levels of Dimethyl Sulfide Diluent
DMS, wt.% 20 C 40 C 60 C 80 C 20 C
0.00 2936.3 502.6 143.6 56.6
2922.7
1.3 1733.8 334.5 106.7 44.6
1624.8
2.6 1026.6 219.9 76.5 34.3 881.1
5.3 496.5 134.2 52.2 25.5 503.5
7.6 288.0 89.4 37.4 19.3 290.0
10.1 150.0 52.4 24.5 13.5 150.5
15.2 59.4 25.2 13.6 8.2 60.7
20.1
29.9 14.8 8.7 5.7 31.0
Table 6
Viscosity (mPa s) of Topped Canadian Asphaltic Crude vs.
Temperature at Various levels of Dimethyl Sulfide Diluent
DMS, wt.% 5 C 10 C 20 C 40 C 60 C 80 C
0.00 579804 28340 3403 732
1.43 212525 14721 2209 538
2.07 134880 10523 1747 427
4.87 28720 3235 985 328
8.01 5799 982 275 106
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9.80 2760 571 173 73
14.81 1794 1155 548 159 64 32
19.78 188 69 33 19
29.88 113 81 51 22 13 8
39.61 23 20 14 8 6 4
Figs. 8, 9, and 10 show plots of Log[Log(Viscosity)] v. Log[Temperature K]
derived from the measured viscosities in Tables 4, 5, and 6, respectively,
illustrating the
effect of increasing concentrations of dimethyl sulfide in lowering the
viscosity of the
crude samples.
The measured viscosities and the plots show that dimethyl sulfide is effective
for
significantly lowering the viscosity of a crude oil over a wide range of
initial crude oil
viscosities.
EXAMPLE 3
Incremental recovery of oil from a formation core using an oil recovery
formulation
consisting of dimethyl sulfide following oil recovery from the core by water-
flooding was
measured to evaluate the effectiveness of DMS as a tertiary oil recovery
agent.
Two 5.02 cm long Berea sandstone cores with a core diameter of 3.78 cm and a
permeability between 925 and 1325 mD were saturated with a brine having a
composition
as set forth in Table 7.
TABLE 7
Brine Composition
Chemical component CaC12 MgC12 KC1 NaC1 Na2SO4 NaHCO3
Concentration (kppm) 0.386 0.523 1.478 28.311 0.072
0.181
After saturation of the cores with brine, the brine was displaced by a Middle
Eastern Asphaltic crude oil having the characteristics as set forth above in
Table 3 to
saturate the cores with oil.
Oil was recovered from each oil saturated core by the addition of brine to the
core
under pressure and by subsequent addition of DMS to the core under pressure.
Each core
was treated as follows to determine the amount of oil recovered from the core
by addition
of brine followed by addition of DMS. Oil was initially displaced from the
core by
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addition of brine to the core under pressure. A confining pressure of 1 MPa
was applied to
the core during addition of the brine, and the flow rate of brine to the core
was set at 0.05
ml/min. The core was maintained at a temperature of 50 C during displacement
of oil from
the core with brine. Oil was produced and collected from the core during the
displacement
of oil from the core with brine until no further oil production was observed
(24 hours).
After no further oil was displaced from the core by the brine, oil was
displaced from the
core by addition of DMS to the core under pressure. DMS was added to the core
at a flow
rate of 0.05 ml/min for a period of 32 hours for the first core and for a
period of 15 hours
for the second core. Oil displaced from the core during the addition of DMS to
the core
was collected separately from the oil displaced by the addition of brine to
the core.
The oil samples collected from each core by brine displacement and by DMS
displacement were isolated from water by extraction with dichloromethane, and
the
separated organic layer was dried over sodium sulfate. After evaporation of
volatiles from
the separated, dried organic layer of each oil sample, the amount of oil
displaced by brine
addition to a core and the amount of oil displaced by DMS addition to the core
were
weighed. Volatiles were also evaporated from a sample of the Middle Eastern
asphaltic oil
to be able to correct for loss of light-end compounds during evaporation.
Table 8 shows
the amount of oil produced from each core by brine displacement followed by
DMS
displacement.
TABLE 8
Oil produced Oil produced Oil produced Oil
produced
Brine displacement Brine displacement DMS DMS
(ml) (of % oil initially in
displacement displacement
core) (ml)
(of % oil initially
in core)
Core 1 4.9 45 3.5 32
Core 2 5.0 45 3.3 30
As shown in Table 8, DMS is quite effective for recovering an incremental
quantity
of oil from a formation core after recovery of oil from the core by
waterflooding with a
brine solution¨recovering approximately 60% of the oil remaining in the core
after the
waterflood.
The present invention is well adapted to attain the ends and advantages
mentioned
as well as those that are inherent therein. The particular embodiments
disclosed above are
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illustrative only, as the present invention may be modified and practiced in
different but
equivalent manners apparent to those skilled in the art having the benefit of
the teachings
herein. Furthermore, no limitations are intended to the details of
construction or design
herein shown, other than as described in the claims below. While systems and
methods are
described in terms of "comprising," "containing," or "including" various
components or
steps, the compositions and methods can also "consist essentially of" or
"consist of' the
various components and steps. Whenever a numerical range with a lower limit
and an
upper limit is disclosed, any number and any included range falling within the
range is
specifically disclosed. In particular, every range of values (of the form,
"from a to b," or,
equivalently, "from a-b") disclosed herein is to be understood to set forth
every number
and range encompassed within the broader range of values. Whenever a numerical
range
having a specific lower limit only, a specific upper limit only, or a specific
upper limit and
a specific lower limit is disclosed, the range also includes any numerical
value "about" the
specified lower limit and/or the specified upper limit. Also, the terms in the
claims have
their plain, ordinary meaning unless otherwise explicitly and clearly defined
by the
patentee. Moreover, the indefinite articles "a" or "an", as used in the
claims, are defined
herein to mean one or more than one of the element that it introduces.
33
